Subsea pipeline service skid

ABSTRACT

Apparatus and methods are described for subsea pipeline servicing, including line-pack testing, physical integrity testing, recovery of damaged sections of pipelines, and product removal from subsea structures. In one embodiment of the invention, a subsea pipeline service skid is provided including at least one sample collection bladder affixed to the skid and in fluid communication with a skid mounted pump dimensioned to pull a sample from the subsea pipeline. In another embodiment, a product removal bladder is provided for removal of the hydrocarbons from a subsea structure.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application60/889,478 filed Feb. 12, 2007 and Patent Cooperation Treaty ApplicationPCT/US08/53733 filed on Feb. 12, 2008, which are incorporated herein byreference.

FIELD OF THE INVENTION

This invention relates apparatus and methods for service of subseapipelines, including chemical sampling and treatment thereof, as well aswet buckle remediation and pipeline integrity testing.

BACKGROUND OF THE INVENTION

Without limiting the scope of the invention, its background is describedin connection with novel apparatus and methods for service of subseapipelines.

It is currently estimated that approximately 60% of the world'spetroleum production derives from offshore operations. To meet demands,and in an environment of increased values for oil and gas, explorationand subsequent production is being undertaken in deeper and deeperwaters. For example, oil and gas is now being produced off the Louisianacoast in 9,000 feet of water. These offshore efforts have requiredexpensive specialized solutions including establishment of extensivenetworks of subsea pipelines for transport of oil and gas from wellheads to gathering structures, hub facilities and to onshore processingrefineries.

The cost of laying pipelines subsea is immense and, therefore, thepipelines are carefully managed and serviced to extend their workablelives. Pipelines running from large fields are engineered to have adesign life of thirty to fifty years. Occasionally pipelines or “flowlines” are damaged during laying of the pipe, or as a consequence ofsubsequent physical damage or environmental conditions. Excessivebending of pipe results in structural damage including buckling. Wheredamage results in a crack in the pipe and fluid inflow this is termed a“wet buckle.” Whether occurring during laying or thereafter, sections ofbuckled pipeline must be removed from the pipeline and repaired.

In one method of recovering wet buckled pipe disclosed in U.S. Pat. No.5,044,827 (Gray et al.), a submersible vessel (“SV”) is used to inflatelift bags beneath the submerged pipeline followed by cutting out thedamaged section of pipe. Finally, the SV inserts a recovery head into anend of the cut pipe to grip the pipe for winching to the surface. Inorder to lift the damaged sections to the surface, wet buckled pipe mustbe evacuated of fluid or “dewatered” to reduce its weight. As describedby Gray, pipeline sections typically are dewatered using topside pumpsto provide compressed gas to drive a dewatering pig from the surfacethrough the pipeline, stopping at the subsea recovery head.Alternatively, as described in U.S. Pat. No. 3,777,499 (Matthews), onesubsea end of the pipeline can be sealed with a cap that includes a gasinlet and gas supplied from the surface can be introduced from one endwhile liquids are pumped from the other end using a pump lowered andpowered from the surface and disposed at the other end of the pipeline.

Compressed gas for driving a dewatering pig must be provided atsufficient pressure to drive the pig considering several dynamiccomponents including: the hydrostatic pressure of the water over thepipe, the friction pressure of the fluid as it moves through the pipe,and the friction of the pig against the pipeline walls (pigdifferential). Because hydrostatic pressure is by far the mostsignificant dynamic component as water depth increases, topsidedewatering has required very large top-side air compression spreads thatmust remain in position over the damaged pipelines during recoveryefforts. What are needed are subsea apparatus and methods able toprovide recovery of damaged pipeline that avoid the need for largetopside gas compressor spreads and/or topside powered dewatering pumps.

Another required pipeline service relates to chemical sampling andtreatment. Sections of pipeline that are waiting to be put into service,or that have been damaged and are awaiting remediation, are typicallychemically treated to prevent corrosion. In addition, in-servicepipelines may become clogged with contaminants that reduce flow,particularly where the pipelines carry a number of different products inmultiphase flow. These include hydrates, asphaltenes, scale, andparaffins. For each of these contaminants and build-ups, specificremediative chemical treatments have been developed and are oftencombined with pigging to physically clean the pipeline and to load thepipeline with the remediative chemicals. Pigging is typicallyimplemented via surface power wherein power fluid or gas is conveyed toa subsea pipeline manifold via coiled tubing run from the surface.Likewise, chemical injection pumps are typically located topside.Testing for the efficacy of the remediative chemical treatment hastraditionally been done by modeling of supposed subsea conditions,including factors of temperature, pressure and the type of productcarried in the pipeline. Actual subsea sampling of pipeline sections hasnot heretofore been possible.

In some cases, service is required on a portion of a subsea product orflow line system that has been in service and contains hydrocarbonproducts. Removal of the product to the surface without environmentalrelease of the hydrocarbon product has heretofore required connection tothe surface via coiled tubing or drill string or has required completedecommissioning and recommissioning. Subsea removal of product has notbeen heretofore possible and represents an unmet need in the industry.

Another heretofore underserved pipeline service relates to leakdetection, where the presence of a wet buckle must be detected, or moregenerally where the continued ability of a pipeline both to contain itscontents, and to protect the contents from in-flow may need to beassessed. In the past, testing for leaks has generally required puttingin place a means to monitor changes in pressure, or alternatively thefacility to detect noise made by leakage.

What are needed are subsea pipeline service apparatus and methods ableto detect leaks in pipelines, to dewater pipelines such that damagedpipelines can be lifted for repair, as well as apparatus and methodsable to provide sampling of the in situ chemical mileu of chemicallytreated pipelines, remove product from flowline system elements, and, ifdesired, to treat sections of pipeline, all using a completely subseaservice skid.

BRIEF SUMMARY OF THE INVENTION

The present invention is directed to a methods and apparatus for subseapipeline servicing, including line-pack testing, physical integritytesting, removal of hydrocarbon product, and recovery of damagedsections of pipelines.

In one embodiment of the invention, a sample collection bladder isprovided for collecting samples of pipeline lie-pack solution subsea. Infurther embodiments, the chemical sampling bladder is in fluidcommunication with a filtration system, wherein any chemicals disposedwithin the pipeline that are not collected in the bladder are flushedthough the filtration system and thereby purified prior to any ambientdischarge. In some embodiments, the sample collection bladder is fittedwith a hydraulic compensator to control discharge of fluid during returnto the surface. In one embodiment of the invention the chemical samplingbladder together with any associated filtration systems and othermechanisms is affixed to a subsea pipeline service skid and is in fluidcommunication with a skid mounted pump dimensioned to pull a sample fromthe subsea pipeline. In one embodiment of the invention the chemicalsampling bladder is located within the skid frame. Alternatively, thebladder may be mounted or strapped on the outside of the skid frame.Preferably the pump is operated by a hydraulic motor powered by an SV,ROV or AUV that transports the skid to the subsea location.

In some embodiments, the skid further includes at least one chemicaltreatment bladder for redosing the pipeline with chemicals after removalof the sample. The skid may further include a chemical dosing pump.

In one embodiment of the invention, methods and apparatus are providedfor subsea removal of product from a pipeline containing hydrocarbonproduct. The apparatus includes at least one product removal bladderdimensioned to contain product removed from subsea jumpers or risers. Inone embodiment of a method for product removal, hydrocarbon is pulled orpushed out by pump action or allowed to float up out of a jumper orriser by influx of lower density seawater under the hydrocarbon product.

In certain embodiments, the skid includes a pump that is dimensioned toreduce pressure in the pipeline by approximately 200 p.s.i. in order totake a sample. In certain embodiments where sampling is to take placeunder conditions of extreme pressure, the pump is a high pressure pumpdimensioned to reduce pressure by 200 p.s.i. under hydrostatic pressuresfrom 400 to 4000 p.s.i. In other shallow water embodiments, the pump isnot required to be a high pressure pump.

In one embodiment of the invention a subsea pipeline service skid isprovided that includes at least one skid mounted high pressure pumpdimensioned to deliver from about 4,000 to about 20,000 p.s.i. ofpressure and at least one hand pump operable by the SV, ROV or AUV toequalize the pressure between the high pressure pump and aflowline/pipeline prior to initiating fluid communication between thehigh pressure pump and the pipeline.

In one embodiment of the invention, a method of remediation of a wetbuckled pipeline using a subsea pipeline service skid is providedincluding the steps of retaining one open end of the buckled pipelineabove water and exposed to a source of air; cutting the buckled pipelinebelow a damaged section; attaching a valve able closure to the cut end;connecting a pump to the valve able closure and running the pump toreduce pressure in the pipeline and thereby draw air in from theatmosphere to displace the water in the severed section.

In another embodiment of the invention, a method of recovering a sectionof pipeline disposed on a seabed is provided including the steps ofdeploying an SV, AUV or ROV to install termination heads on each offirst and second ends of the pipeline section; providing a source ofcompressed gas to the first end of the pipeline section; utilizing theSV, AUV or ROV to move an SPSS that includes a high pressure pump to thesecond end of the pipeline section and connect the SPSS to thetermination head; and using the SV, AUV or ROV, power the high pressurepump to pull water out of the pipeline and displace fluid in thepipeline with a relatively modest volume of gas from the compressed gassource, thereby dewatering the pipeline; and recovering the dewateredsection of pipeline from the seabed. Optionally, the method furtherincludes inserting a dewatering pig in the first end of the pipelinesection whereby the pig is advanced toward the second end of thepipeline section by a combined sucking action of the pump and pushingaction of the compressed gas.

In another embodiment, a method of subsea pipeline integrity testing isprovided including the steps of providing an SPSS that comprises atleast one high pressure pump and a pressure monitor able to detect achange in pressure of about 1 p.s.i. or less; utilizing an SV, AUV orROV to move the SPSS to a subsea section of pipeline, wherein a pipelinetermination head is affixed to each end of the pipeline section; usingthe SV, AUV or ROV to power the high pressure pump to pull water out ofthe pipeline and thereby reduce pressure in the pipeline below ambientpressure around the pipeline; and monitoring pressure in the pipeline todetermine if any in-flow leakage occurs sufficient to change pressure inthe pipeline. In one such embodiment, the high pressure pump isdimensioned to reduce pressure in the pipeline at a hydrostatic pressureof about 400 p.s.i. In another embodiment, the high pressure pump isdimensioned to reduce pressure in the pipeline at a hydrostatic pressureof up to about 4000 p.s.i.

In another embodiment of the invention, methods and apparatus areprovided for removing a fluid content of a subsea structure, such as forexample a flowline jumper, flowline terminus or manifold, or a Christmastree, including the steps of: providing at least one product removalbladder to the subsea structure, wherein the bladder is fitted with atleast one valve closure and wherein the bladder is dimensioned to draina quantity of the fluid content from the subsea structure; providing anSPSS including at least one pump and a fluid conduit that terminates inan SPSS fluid connector dimensioned to connect with the valve closure ofthe product removal bladder; utilizing an SV, AUV or ROV to connect thebladder and SPSS to the subsea structure; utilizing the SPSS pump tomove fluid content from the subsea structure into the product removalbladder, and returning the product removal bladder to a surface vesselfor disposal. In one method of removing a fluid content from a subseastructure, the SPSS includes intake filters and at least one pump on theSPSS is utilized to pump filtered seawater into the subsea structure andthereby push the fluid content of the subsea structure into productremoval bladder.

Also provided herein are subsea fluid containment skids including atleast one product removal bladder disposed in a cage and dimensioned toeffect removal of a significant portion of a hydrocarbon or other fluidproduct from a subsea structure. By “effect removal of a significantportion” it is meant that the bladder is dimensioned to hold asufficient quantity of product removed from the subsea structure suchthat the structure can be drained with operational efficiency. In onesuch example, the bladder is dimensioned to hold up to about 2000gallons. Larger and smaller bladders are envisioned as well asdeployment of a plurality of bladders that are filled in series forremoval to the surface. In other embodiments, a containment skid isprovided that includes a plurality of bladders for removal of fluidproduct from several subsea structures or different sections of a singlesubsea structure with few trips to the sea floor.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, includingfeatures and advantages, reference is now made to the detaileddescription of the invention along with the accompanying figures:

FIG. 1 illustrates removal of a section of wet buckled pipeline wherethe damaged pipe section remains attached to the laying vessel and thushas one end exposed to ambient air.

FIGS. 2, 3 and 4 depict use of an SV to transport a chemical samplingbladder to a pipeline section disposed between two PLETs, and its use toextract a sample of the pipeline contents for transportation to thesurface. The same figures illustrate an embodiment of a process to checkfor the presence of leaks.

FIG. 5 depicts an oblique view of a chemical sampling bladder accordingto one embodiment of the invention.

FIG. 6 depicts an end view of a chemical sampling bladder according toone embodiment of the invention.

FIG. 7 depicts a top view of a chemical sampling bladder according toone embodiment of the invention.

FIG. 8 depicts a side view of a chemical sampling bladder according toone embodiment of the invention.

FIG. 9 depicts a one embodiment of a subsea pipeline commissioning skid(SPCS) to which a chemical sampling bladder can be attached.

FIGS. 10, 11 and 12 provide further perspective views of the SPCS ofFIG. 9.

FIG. 13 depicts an SPSS recovering product from a subsea structure bypumping seawater into the structure and thus pushing the product into aproduct removal bladder.

FIG. 14 depicts an SPSS recovering product from a subsea structure bypulling product out of the structure and into a product removal bladder.

FIG. 15 depicts an embodiment of an SPSS including an affixed productremoval bladder.

FIG. 16 depicts an embodiment of a containment skid including a productremoval bladder.

FIG. 17 depicts an embodiment of an affixed product removal bladderincluding a hydraulic compensator.

FIG. 18 depicts an embodiment of an affixed product removal bladderincluding a drag reducing shroud.

DETAILED DESCRIPTION OF THE INVENTION

While the making and using of various embodiments of the presentinvention are discussed in detail below, it should be appreciated thatthe present invention provides many applicable inventive concepts whichcan be employed in a wide variety of specific contexts. The specificembodiments discussed herein are merely illustrative of specific ways tomake and use the invention and do not delimit the scope of theinvention.

To facilitate the understanding of this invention, a number of termsand, in some cases, related abbreviations, are defined below. Termsdefined herein have meanings as commonly understood by a person ofordinary skill in the areas relevant to the present invention. Termssuch as “a”, “an” and “the” are not intended to refer to only a singularentity, but include the general class of which a specific example may beused for illustration. The terminology herein is used to describespecific embodiments of the invention, but their usage does not delimitthe invention, except as outlined in the claims.

For purposes of the present invention, the term Pipeline End Termination(“PLET”) defines a valved closure for a pipeline. However, the term PLETalso refers to large subsea collection hubs including a plurality ofpipeline terminations and valved closures. Such hubs can be dimensionedto connect a number of flowlines carrying oil and gas from variousfields to production lines that may run, for example, to onshorefacilitates.

As used herein, the abbreviation “SV” refers to a Submersible Vehiclethat is operated by human operators in the SV. In contrast, as usedherein, the abbreviation “ROV” refers to a tethered Remote OperatedVehicle that is operated from the surface remotely. The abbreviation“AUV” refers to untethered Autonomous Underwater Vehicles.

As used herein, the abbreviation “SPCS” refers to a subsea pipelinecommissioning skid according to one embodiment of the invention.Pipeline commissioning is a multistep process that includes flooding ofthe subsea pipeline, running a pig through the pipeline to test forinternal structural integrity, and hydrostatic pressure testing toinsure both structural integrity and to test for leaks. Typically,hydrostatic pressure testing requires the pipeline to be placed atpressure for an interval sufficient to demonstrate its ability towithstand its intended operational pressure. Pressures and times forhydrotests will vary depending on the requirements of the end-user ofthe pipeline, and the regulatory regime that applies in the locale wherethe pipeline is being constructed. These will be as a minimum a test tothe maximum operating pressure (MAOP) for at least four hours. Moretypically test pressure will be held for at least twenty-four hours, andwill be some specified percentage of either MAOP or that pressurerequired to reach some percentage of specified minimum yield stress(SMYS) in the pipe material. The pressure required to perform the testdepends directly on the depth of the water where the pipeline is locatedbecause the baseline pressure is the hydrostatic pressure at the givendepth.

As used herein, the abbreviation “SPSS” refers to a subsea pipelineservice skid according to one embodiment of the invention. The SPSS isnot limited to pipeline commissioning but may be employed to service thepipeline subsequent to commissioning, including for example chemicalsampling to determine the status of a pipeline that has been shut-in fora period of time, hydrostatic testing where damage to the pipeline issuspected or has been remediated, checking for inward leakage,dewatering of the pipeline for raising the pipeline from the seabed tothe surface, product removal for pipeline system repair, as well aspigging to clean pipelines of in-service contaminants. The terms SPCSand SPSS are used interchangeably herein to refer to a subsea skidincluding at least one pump. In one embodiment of the invention, theSPCS or SPSS will include at least one high pressure pump of sufficientpower to exceed hydrostatic pressure at depths of up to 10,000 feet ofwater.

The following examples are included for the sake of completeness ofdisclosure and to illustrate the methods of making the compositions andcomposites of the present invention as well as to present certaincharacteristics of the compositions. In no way are these examplesintended to limit the scope or teaching of this disclosure.

Example 1 Subsea Pipeline Service Skid

One embodiment of the present invention provides a Subsea PipelineService Skid (“SPSS”) that includes at least one high pressure pump thatis able to overcome the hydrostatic pressure of water up to and over10,000 feet deep. Hydrostatic pressure P (in pascals, Pa) is equal toρgh, where ρ (rho) is the water density in kilograms per cubic meter, gis gravitational acceleration in meters per second squared, and h is theheight of fluid above in meters. Although water density changes withtemperature, for purposes of ready calculation, a ρ value of 1027 kg/m³(density of seawater at 5°) will be used. Ignoring changes ingravitation as one departs from the earth's surface, a constant valuefor g of 9.8 m/s² can be used. Using these constants for ρ and g, it canbe calculated that the hydrostatic pressure of 1000 feet of water (304.8meters) is 3.07×106 Pa (P=1027×9.8×304.8), which converts to 445p.s.i.(1 p.s.i.=6894.76 Pa). For 1000 meters of water, the value isapproximately 1460 p.s.i., while in 9000 feet of water (2743.2 meters),the hydrostatic pressure is approximately 4,004 p.s.i. In 10,000 feet ofwater the hydrostatic pressure is approximately 4,449 p.s.i. Thus, inthe context of certain embodiments of the present invention, the term“high pressure pump” means a pump capable of continuing to deliver flowin situations where ambient pressure at both suction and discharge maybe in excess of 400 p.s.i. In certain embodiments, the high pressurepump will be able to continue to deliver flow in situations whereambient pressure at both suction and discharge may be in excess of 4000p.s.i.

In one embodiment of the invention, the SPSS provides a physicalframework facilitating the full range of pre-commissioning andpost-commissioning activities to be carried out on deepwater pipelines.To this end it is designed to carry several different pieces ofequipment, depending on the details of the job in hand. One embodimentof a suitable SPSS is depicted in FIG. 9. Power is suppliedhydraulically from an ROV or other source (AUV, SV). The minimum powerrequired by the SPSS from this source will be approximately 70HP. Takinginto account other power requirements in running the ROV, the totalhydraulic power requirement to provide 70HP would be approximately100HP. More power may be required in certain applications. The SPSS ispreferably provided with buoyancy, such as by one or more buoyancycompensator(s) (20), shown in FIGS. 9, 10, 11 and 12, in order that itcan approximate neutral buoyancy at various depths. This facilitatesmaneuverability of the SPSS by the ROV, AUV or SV.

One embodiment of a suitable SPSS (40) is depicted in FIGS. 9-12. SPSS(40) includes a rigid frame (1) which is attachable to the SV, AUV orROV via ROV mounting plate (13). The SPSS includes a high pressure pump,suitable for hydrotest and other operations. This pump must be capableof raising the pressure in the pipeline to the required test pressure,i.e. at least the specified maximum operating pressure, and generallysome pressure higher than this. This pump will generally have to becapable of delivering sufficient flow to raise the pressure in the lineat an acceptable rate, such as for example, a typical rate of 3-5 gpm,or 1 psig/minute. Pumps of positive displacement type are generallysuitable for this service. In the embodiment depicted in FIGS. 10 and12, a triplex type pump (2) connected via flexible coupling (25) to andoperated by hydraulic motor (5) is employed. In one embodiment for lowerdepth applications, the pump is capable of providing a flow of 3-5 gpmat a hydrostatic pressure of approximately 400 p.s.i. with a minimumsuction head of 30 p.s.i. In another embodiment dimensioned for deeperwaters, the pump is capable of providing a flow of 3-5 gpm at ahydrostatic pressure of approximately 4000 p.s.i. with a minimum suctionhead of 30 p.s.i. In another embodiment, the pump is very high pressurepump able to deliver a flow of 3-5 gpm at a line pressure of 20,000p.s.i. with a minimum suction head of 30 p.s.i.

One or more filters (10) are required at the pump inlet able to filterout particles down to fifty microns or lower in size. The triplex pump(2) can be disposed in an optional pump cage (3) as depicted in FIG. 11.Likewise, FIG. 11 depicts an embodiment where a backflush pump (notshown) is protected in backflush pump housing (9). The top view providedby FIG. 11 shows a 1″ male stab (14) as well as bleed valve (24),instrument isolation valve (23), and double block (22). Also depictedare the ROV attachment posts (27).

In one embodiment of the invention, the skid also includes a chemical ordosing pump (11) operated by hydraulic chemical pump motor (12), whichis suitable for the injection of corrosion inhibitor and/or otherchemicals that are transported on the skid by one or more chemicaltreatment bladders (6). Flow metering, such as is provided by flow meter(18) is present on the skid to provide a record of quantities of waterpumped into the line/quantities of chemicals dosed. A pressure reliefvalve (19) is located in the flow line.

When outfitted for hydrotest purposes, the skid includes a data logger(21) and storage capability for pressure and temperature monitoring asis required during hydrotesting. The capability is typically provided bytransducers for the measurement of the line pressure and temperature,with data being recorded into non-volatile memory. The SPSS may beprovided with visual displays including stroke counter display (17),capable of being read by an ROV-mounted camera. The stroke counterdisplay records the activity of stroke counter (16) depicted in the topview of FIG. 11. Alternatively, telemetery between the datalogger andthe surface is provided. In one embodiment, a data communication linkcapable of connecting through the ROV to the surface providing areal-time read-out of values is also included. High accuracy/highstability measurements are needed for this application, as the data iscritical to the assessment of pass/fail criteria for the hydrotest. Inone embodiment of the invention, the SPSS logger has the ability tomeasure pressure to an accuracy of +/−0.02%, and temperature to anaccuracy of +/−0.1° C.

A dewatering pump may also be present, capable of pushing a pig-trainthrough the line. The high pressure pump that is dimensioned forhydrostatic testing may generally be suitable for this service.Additional pumps may be present on the skid to provide other services,such as for instance a backflush pump (8) together with backflush pumpfilter (4), depicted in FIGS. 10-12, to maintain the seawater filters ina state of continued efficacy, and a chemical injection or dosing pumpdescribed above. As depicted in FIGS. 10 and 11, an oil compensationunit (7) is optionally included and is preferably located in conjunctionwith the hydraulic pumps.

In one embodiment of the invention and as depicted in FIGS. 9-12, theskid includes a particular safety feature that is designed to preservethe integrity of connections between the pipeline and the high pressurepump. The discharge manifold and pressurization hose/hot stab of theSPSS are short in comparison to the entire length of the pipeline.Because regulation of hydraulic power to the triplex pump is difficultonce it is engaged, direct unregulated connection of the triplex pump tothe discharge manifold and pressurization hose/hot stab could pressurizethe hose extremely quickly and possibly even burst the hose.Furthermore, the pressure transducers on these lines are extremelysensitive to shocks, particularly when employing quartz crystalresonators. Therefore, SPSS (40) includes a hand pump (15), depicted inFIGS. 9, 10, 11 and 12, to equalize the pressure between the skidmounted pump and the flowline/pipeline before the valve separating thetwo is opened.

For example, when the system is pressurized to test pressure and mustremain so for a prolonged period, such as a twenty-four hour hydrotestperiod, and it is desirable to disconnect the ROV from the system inorder to perform other work, the valve of the PLET cap is isolated, thepressurization hose/hot stab of the SPSS is depressurized and the SPSSis disconnected from the ROV and left in position on the pipeline. Ifthe pressure drops for any reason or if it becomes desirable topressurize once the test was complete, the hose would be reconnected tothe PLET. The hand pump (15) would then be operated using the ROVmanipulator to pressurize the hose in a slow and controlled manner andthereby equalize the pressure across the PLET valve. The valve wouldthen be opened and the high pressure pump functionally engaged with thesystem.

Example 2 Wet Buckle Remediation where the Pipeline Remains Attached tothe Laying Barge

Occasionally when a pipeline is being laid, irregularities in thecharacteristics of the pipeline may suggest that the integrity of thepipeline may have been compromised such as by either a wet or drybuckle. Typically, a wet buckle will result in in-flow of water into thepipeline, which makes the pipeline begin to get heavier. In one solutionto wet buckle remediation, the buckled pipe is still attached to thelaying barge (100) as depicted in FIG. 1. An SV, AUV or ROV (118) isused to cut the pipeline (116) below the wet buckle (115). The SV, AUVor ROV then attaches a valvable closure (117), preferably including hotstab connections, to the bottom end of the pipeline. The SV, AUV or ROVis employed to carry a SPSS to the bottom end of the pipeline. The SPSSincludes a high pressure pump able to deliver pressures across the rangeof 100-20,000 p.s.i. of pressure. The high pressure pump is connected tothe valvable closure and the SV, AUV or ROV powers the pump to pullwater out of the pipeline. Air, or alternatively nitrogen or other inertgas from the surface end of the pipe, displaces the water as it ispumped out of the pipe. The pipe is thus dewatered and un-weighted forrecovery by the laying barge.

Example 3 Remediation of a Damaged Section of Pipeline Disposed on theSeabed

Where a wet buckle is suspected the pipeline may be dropped from thelaying vessel and checked for damage and later remediation. However, theaction of dropping the pipeline will result in filling of the pipeline.In order to raise the pipeline to the surface, the pipeline must beemptied. This is undertaken by using an SV, AUV or ROV (118) to installtermination heads such as valvable closures (117), preferably includinghot stab connections or abandonment, recovery or initiation laydownheads on each end of the pipeline as depicted in FIG. 2. A dewateringpig may be inserted in one end of the pipeline and a source ofcompressed air or nitrogen/other inert gas attached behind the pig.Alternatively in some circumstances the pig may not be required, andonly the gas source used. In one embodiment the gas source is providedsubsea to displace sufficient water to reduce weight and recover thepipe. The SV, SUV or ROV then moves an SPSS according to the inventionto the opposite end of the pipeline and utilizes its robotic arm (119)to connect the high pressure pump of the SPSS to the hot stab connection(124) of the pipeline termination head as depicted in FIG. 4. The highpressure pump is characterized by the capacity to deliver pressuresacross the range of from 100-20000 p.s.i. of pressure. The SV, AUV orROV powers the pump to pump water out of the pipeline in accordance withthe following parameters.

For purposes of pigging, several dynamic components are involved in theamount of pressure needed to drive a subsea pigging unit (“SSPU”): thehydrostatic pressure of the water over the pipe, the friction pressureof the fluid as it moves through the pipe, and the friction of the pigagainst the pipeline walls (pig differential). Compared with thehydrostatic pressure, which changes dramatically with water depth, thefriction pressure and the pig differential are relatively insignificant.The pressure required to drive a dewatering pig through a floodedpipeline in 1000 meters of water, taking for example, a 30 psi pigdifferential (assuming movement of the pig at approximately 0.5meters/sec) and a 30 psi friction loss can be calculated as 1497 p.s.i.(hydrostatic pressure)+30 p.s.i. (friction loss)+30 p.s.i. (pigdifferential) would be approximately 1560 p.s.i. If the pig is to bedriven solely by the force of a gas as in typical dewateringapplications, the volume of gas that is required is equal to line volumeat a pressure that is 60 p.s.i. over the hydrostatic pressure. Thisrequires a huge top-side compressor skid and an enormous volume of gas.

The present invention solves this problem and avoids the need for suchtop-side gas capacity. In accordance with the dewatering methods of thepresent invention, the pig is effectively pulled though the pipeline byusing the SV, AUV or ROV to attach the pumping skid of the invention tothe end of the pipeline that is distal to the location of the pig andpumping out from the pipeline such that the pig is pulled toward thepump, followed by a relatively modest volume of gas. Because the wateris pumped from the pipeline, the hydrostatic head can be overcome by thepump so that the gas pressure behind the pig need be no higher than thatrequired to overcome friction between the pig(s) and the pipe wall,friction between the column of water and the pipewall, plus the suctionpressure. As a consequence of dewatering, the pipeline is therebysufficiently un-weighted that it can be raised to the surface.

Example 4 Pipeline Physical Integrity Testing

In one embodiment of the invention, testing to locate any potentialdamage is provided by an SPSS that is lowered to the pipeline by an SV,AUV or ROV. The SPSS includes at least a high-pressure pump havingsufficient capacity to reduce the pressure in the pipeline to below theambient hydrostatic pressure to check for in-flow leaks. In accordancewith one embodiment, the high-pressure pump is defined as having apumping capacity able to deliver 20,000 p.s.i. of pressure in a positivedisplacement mode, and a pressure monitoring capability able to detect achange in pressure of less than 1 p.s.i. High flow rates are notnecessarily required, i.e. a low flow-rate of a minimum of approximately3 gpm would suffice. The method used is to pump water out of the linethus lowering the pressure in the line, volumes pumped to achieve thiswill be small compared to total volumes in the line. Pressure is thenmonitored to detect increases in pressure (back toward ambient)indicating that seawater is leaking into the line. In one embodiment ofthe invention, the integrity of the pipeline is further analyzed by useof hydrophones conveyed along the pipeline by the SV, AUV or ROV.

Example 5 Testing for Corrosion in Subsea Pipelines

Development of a deep-water offshore field anchored around aproduction-drilling-quarters (PDQ) platform is an immense undertaking,typically costing in excess of one billion dollars for theinfrastructure. Such developments may be anchored in (very) deep water,at depths of 6,000 ft or more. These platforms will be used to gatherproduction from multiple wells, producing both oil and gas. Reservoirpressures and temperatures for these deepwater developments are also atthe extremes, and production can be at pressures over 17,000 p.s.i. andtemperatures of 135° C. Extreme weather conditions offshore canfrequently cause significant delays, or lead to relatively shortconstruction seasons, and projects of this type can often extend overseveral years. Even under best conditions it can take months or yearsbetween the laying of subsea flowlines and first production. During thisperiod the flowlines are filled with a chemical “line-pack” solutionthat may include corrosion inhibitors, oxygen scavengers and biocides,among others.

Chemical additives are available that are specifically tailored tovarious indications. In addition to the aforementioned corrosioninhibitors, oxygen scavengers, and biocides, typical chemical additivesfor treating pipelines include leak testing dyes, and hydrate,asphaltene, scale, and paraffin inhibitors.

In other circumstances in fields that have already been put intoproduction, it is occasionally necessary to shut-down some or all of theflow-lines associated with a particular field or host platform. Forexample, damage to the host platform may necessitate shutting down theflow-lines until the platform is repaired. For shut-down, the flow-linesare filled with a chemical “line-pack” solution as previously described.In a further circumstance, production from certain smaller fields orwells within such fields may be shut-in to conserve reservoir pressureor because production is uneconomic at certain times. The flow-lines tothese wells and field may be later reopened and connected to larger hubfacilities via tie-backs. The availability of a hub facility may changethe economics of production from the smaller fields. Meanwhile, thesmaller field flow-lines are shut-in with chemically treated line-packsolutions. However, in order to safely reopen the production lines, itis desirable, if not necessary, to test the status of the chemicalstatus of the line-pack solutions to ascertain whether the flow-lineintegrity has been compromised or whether corrosion, hydrate formation,etc. has occurred.

Heretofore, it has not been possible to test the status of the line-packsolution subsea. The present invention provides a solution to this needby providing methods and apparatus for subsea collection of actualsamples of sufficient quantity to be able to determine whether theline-pack has provided suitable protection against corrosion orcontamination. In one embodiment, a subsea chemical sampling bladder isprovided and is transported to the pipeline section for collection ofthe samples. The sample shall be drawn from at least one end, andpreferably from each end, of the flow-line. In one embodiment thebladder implement is transported to the pipeline section via an SPSSthat includes a pump dimensioned to reduce the pressure in the pipelinesufficiently enough to collect sample(s). The SPSS shall be deployed andpowered by an SV, AUV or ROV, depending on the water depth andavailability. If any of the linepack fluids are not required to formpart of the sample, these can be discharged through a filter, such as acarbon filter, to neutralize the chemicals prior to discharge into theenvironment. Each sample shall be recovered to the surface, refrigeratedand returned to a testing facility for analysis.

Specifically, as depicted in FIG. 3, an SPSS (40) will be deployed froma support ship (100) using an SV, AUV or ROV (118). In the case of theROV depicted, connection to the ship is provided by a tether managementsystem (“TMS”). The ROV transports the SPSS to a section of flowline(116) to be tested. In the embodiment depicted in FIG. 4, the flowline(116) is sealed on each end by PLETs (120), each of which will typicallyinclude a valved closure (122) and may further include a valved port(123) that is adapted as a hot stab-able connection (124).

An embodiment of a chemical sampling appliance (128) is depicted inFIGS. 5-8. The appliance includes sample collection bladder (32) securedwithin frame structure (34) that includes connecting means (50) forfixing the appliance to the SPSS and may optionally include liftinghandles (52). In other embodiments, one or more bladders are strapped oraffixed to the outside of the frame structure. Placement of the bladderon the outside of the frame provides considerable latitude indimensioning the bladder. In certain embodiments, the outer bladder isprotected by a cage structure. The bladder may be formed of any materialable to provide a leak proof enclosure and able to withstand extremes oftemperature and pressure. In one working embodiment of the invention,the bladder was formed of a proprietary elastomeric material (L4284UPWfrom Cooley Inc.) Other suitable materials are or may become available.In the embodiment depicted in the end view of FIG. 6, the piping (38) tothe bladder includes a quick connect type connector (36) and on-offvalve closures (54). As further depicted in FIGS. 7 and 8, at least oneof the piping conduits may include a check-valve (56).

In order to take a sample, the suction side of the positive displacementpump shall be connected to the hot stab (124) on the PLET (120) orflowline plug (126) dependent upon the status of the flowline to betested. The pump shall then be engaged and the system will reduce theabsolute pipeline pressure inside the flowline. In general, the pressurereduction required will be controlled by the volume of the samplerequired, the line-pack pressure, and the hydrostatic pressure.Likewise, the required characteristics of the pump will be determined bythese factors. In one embodiment of the invention a SPSS suitable forany condition including extremes of pressure is provided by inclusion ofa high pressure positive displacement pump. For example, in oneembodiment the pressure reduction required in order to extract thisvolume is a reduction below ambient of approximately 200 p.s.i. With thehigh pressure pump, a pressure pulled will not be less than a minimumpump suction pressure of 30 p.s.i. to avoid cavitation of the pump. Forline lengths of 10,000 to 15,000 ft, and diameters of 8″-12″, areduction in pressure of 200 p.s.i. will extract over ten gallons ofliquid. This shall be achieved by pumping line-pack water (30) out ofthe flowline and through a sample bladder of the chemical samplingappliance (128) where a representative portion of it shall be collectedand ultimately returned to the surface/beach for analysis.

In one embodiment a representative sample is collected “mid-stream” orafter a volume of line-pack has flushed through the bladder. Anothercriterion that contributes to a representative sample is to collect asufficient volume of sample from at least one and preferably both endsof the flow line. For example, in the embodiment depicted in FIG. 5, thebladder has an approximate collection volume of one gallon, althoughlarger or smaller volumes may be in other cases desirable.

In one embodiment, a carbon or other chemical absorbent filter isdisposed in fluid connection with an effluent outlet from the samplecollection bladder to neutralize or collect chemicals present in theline-pack prior to discharging that part of the line-pack that is pumpedout and not retained as part of the sample. In one embodiment, a datalogger system is used to monitor pressure, temperature and volumepumped. Volume may either be directly measured using a flowmeter, orcalculated using a stroke counter, to provide an indication of when therequired volume of the line-pack fluid has been pumped. When theoperation is complete, the SPSS shall disconnect from the flowline, andbe moved back to the surface by the ROV (SV, AUV). As depicted in FIG.18, the chemical testing bladder may be fitted with a shroud (346) toreduce effects of drag during return to the surface. Alternatively oradditionally, as depicted in FIG. 17, the sample bladder may be fittedwith a hydraulic compensator (340) in order to control discharge offluid during return to the surface. The sample will be removed foranalysis, and the procedure repeated for any further samples required.

In one embodiment of the invention, following collection of thesample(s), the SPSS is reconfigured and used to pump chemically treatedseawater back into each flowline to bring the internal flowline pressureback up to absolute hydrostatic head. The fresh chemical is preferablyprovided by chemical treatment bladders (6) mounted in or on the SPSSdepicted in FIG. 9. If PLETs are still attached to the flowline and asdepicted in FIG. 4, the flow line can be severed at a cut location (125)between each PLET (122) and each terminal plug (126). The PLETs can thenbe recovered to the surface if desired for testing and refurbishing.

Example 6 Subsea Product Removal

In some cases, service is required on a portion of a subsea product orflow line system that has been in service and contains hydrocarbonproducts. In one embodiment of the invention, methods and apparatus areprovided for subsea removal of such product from a subsea structure suchthat the structure can be serviced. Subsea structures as used hereininclude flowline jumpers, flowline termini or manifolds, Christmas treesor any other subsea structure used to convey fluids subsea.

For example, in one embodiment of the invention product is removed froma subsea flowline jumper. A typical example of a flowline jumper is aconnection between the production outlet of a Christmas tree to apipeline end termination (PLET) or pipeline end manifold (PLEM) orbetween two subsea pipelines. Typically a flowline jumper (300) willinclude at least two fluid couplings (305) connected by a conduit (307).The fluid couplings of the jumper are adapted for connection to matingsockets on other subsea structures. The flowline jumper is typically arigid structure but may alternatively include a flexible conduit. Ineither event the fluid couplings of the flowline jumper are oriented toconnect with termini of pipeline or production outlets, which willtypically include isolation valves such that hydrocarbon product in thepipeline and the production source can be sealed off from the jumper.Under such conditions, hydrocarbon may remain in the jumper or otherstructure that is dead legged from the flowline and production source.

In accordance with the present embodiment, methods and apparatus areprovided for subsea removal of hydrocarbon product from subseastructures such that the structures can be serviced or replaced. In onemethod of product removal depicted in FIG. 13, the SPSS (40) is deployedto a subsea structure such as flowline jumper (300). The depicted jumperis not drawn to represent a relative scale to the SPSS. Indeed thesubsea structure may in many instances be many times the size of theSPSS. The SPSS can be lowered to the sea floor by a cable from thesurface vessel, or can be carried by an SV, AUV or ROV (118), dependingon the water depth and availability. Once on the seafloor, the SV, AUVor ROV can be utilized to make connections and to power the SPSS pumps.In the embodiment depicted in FIG. 13, a containment skid (320) isprovided that includes a product removal bladder (323) disposed in acage structure (325). Depending on its dimensions, the containment skid(320) may be lowered to the seafloor by cable or, alternatively, bemaneuvered by the SV, AUV or ROV. By the use of containment skids,considerable latitude is enabled in dimensioning the bladder. For onenon-limiting example, FIG. 16 depicts a top and side view of anexemplary containment skid having a cage dimension of 24 ft.×8 ft.×3 ft.and including a 2000 gallon bladder. In the embodiment depicted in FIG.16, the bladder (323) includes a valve closure (321) as well as a vent(327) connected to a bleed valve (329).

Product removal can be effected directly using the SPSS pump if thejumper includes outlets that are sufficiently large that directconnection to the SPSS pumps is feasible. However, where a drain outleton the jumper is too small for utilization of the main SPSS pumps,product can be removed from the jumper by relying on the lower specificgravity of hydrocarbons relative to seawater to allow the product tofloat on the water column and thus be displaced with the seawater thatis introduced into the structure from a low point of the structure. Theproduct can then be collected in the bladder and recovered for onshoredisposal.

In one embodiment as depicted in FIG. 13, the SV, AUV or ROV is utilizedto connect the product removal bladder to a high point of fluidcontainment within the subsea structure. A valve inlet or fluid coupling(310) on a low point of the subsea structure (300) is connected to theoutput flow line (330) of the SPSS (40) and a pump on the SPSS isengaged to pump filtered seawater into the low point in order to pushthe remaining product disposed in the subsea structure into the productremoval bladder (320).

Alternatively, as depicted in FIG. 14, the hydrocarbon can be pulledfrom the subsea structure and into the product removal bladder byconnection to an inlet of an SPSS pump. In some embodiments, a jumper isin fluid connection to a PLET or PLEM or other subsea structure and anoutlet on the far end of the structure is opened such that product canbe drained from the structure though the jumper and ultimately into theproduct removal bladder.

In some cases, the jumper connection is characterized by a fluid volumethat can be removed into a subsea bladder that can be manipulated andbrought to the surface by an SV, ROV or SUV in a single trip. In othercases however, the jumper may include a volume exceeding that which canbe carried in one trip. In one embodiment of a solution provided by thepresent disclosure, product is removed from the large volume jumper bydeploying a plurality of product removal bladders to the sea floor,which are filled sequentially for recovery to the surface after filing.

In other embodiments where smaller volumes are to be removed at leastone product removal bladder is strapped or affixed to the outside of theframe structure (1) of the SPSS (40) as depicted in FIG. 15. Placementof the bladder on the outside of the SPSS frame provides considerablelatitude in dimensioning the bladder. FIG. 15 depicts the productremoval bladder affixed under the pumping skid of the SPSS. In otherembodiments, the product removal bladder is affixed to one or more sidesor the top of the pumping skid. Further separate bladders can bedeployed if necessary. The SPSS together with affixed or separatebladders can deposited on the sea floor and the SV, AUV or ROV can thendisconnect from the SPSS for manipulation of valves, umbilicals, etc.

All publications, patents and patent applications cited herein arehereby incorporated by reference as if set forth in their entiretyherein. While this invention has been described with reference toillustrative embodiments, this description is not intended to beconstrued in a limiting sense. Various modifications and combinations ofillustrative embodiments, as well as other embodiments of the invention,will be apparent to persons skilled in the art upon reference to thedescription. It is therefore intended that the appended claims encompasssuch modifications and enhancements.

1. A subsea pipeline service skid comprising: a frame adapted fortransporting the skid to a subsea pipeline; at least one samplecollection bladder affixed to the frame and in fluid communication witha pump mounted in the frame and dimensioned to pull a sample from thesubsea pipeline, the pump operated by a hydraulic motor powered by aSubmersible Vehicle (SV), a Remote Operated Vehicle (ROV), or anAutonomous Underwater Vehicle (AUV); and a fluid conduit adapted toconnect between the subsea pipeline and the frame mounted pump.
 2. Theskid of claim 1, further comprising a chemical dosing pump and achemical treating bladder mounted in the frame.
 3. The skid of claim 1,wherein the fluid conduit includes a hot stab connection.
 4. The skid ofclaim 1, further comprising a filtration system in fluid communicationwith the at least one sample collection bladder, wherein chemicalsdisposed within the pipeline prior to sampling are flushed though thefiltration system and thereby purified prior to ambient discharge. 5.The skid of claim 1, wherein the pump is a high pressure pumpdimensioned to deliver pressure across a range of 100 to 20,000 p.s.i.6. The skid of claim 1, wherein the at least one sample collectionbladder is in fluid connection with an effluent filter dimensioned toneutralize or collect chemicals present in a linepack in the subseapipeline prior to discharging a part of the line-pack fluid that ispumped out and not retained as part of a sample retained in the at leastone sample collection bladder.
 7. The skid of claim 1, furthercomprising a shroud dimensioned to reduce effects of drag on the atleast one sample collection bladder during return to from the subseapipeline.
 8. The skid of claim 1, wherein the at least one samplecollection bladder is fitted with a hydraulic compensator to controldischarge of fluid during return to the surface.
 9. The skid of claim 1,further comprising at least one chemical treatment bladder for redosingthe pipeline with chemicals after removal of the sample.
 10. The skid ofclaim 9, further comprising a chemical dosing pump for controlledredosing of the pipeline with chemicals after removal of the sample. 11.The subsea pipeline service skid of claim 1, wherein the at least onesample collection bladder is elastomeric.
 12. The subsea pipelineservice skid of claim 11, wherein the at least one sample collectionbladder is disposed within a cage.
 13. A subsea pipeline service skidcomprising: a frame adapted for transporting the skid to a subseaflowline/pipeline; at least one high pressure pump mounted to the frameand dimensioned to deliver over 4,000 p.s.i. of pressure; and at leastone hand pump in fluid communication with the at least one high pressurepump and operable by a Submersible Vehicle (SV), a Remote OperatedVehicle (ROV), or an Autonomous Underwater Vehicle (AUV) to equalize thepressure between the at least one high pressure pump and the subseaflowline/pipeline prior to initiating fluid communication between the atleast one high pressure pump and the subsea flowline/pipeline.
 14. Amethod of testing a status of a line-pack in a subsea pipeline,comprising the steps of: providing at least one elastomeric samplecollection bladder in fluid communication with a subsea pump, whereinthe pump is dimensioned to pull a sample of line-pack from the subseapipeline; utilizing a Submersible Vehicle (SV), a Remote OperatedVehicle (ROV), or an Autonomous Underwater Vehicle (AUV) to move the atleast one elastomeric bladder and the pump to a pipeline terminationhead affixed to one end of the subsea pipeline; collecting a sample ofthe line-pack by pumping a portion into the at least one elastomericsample collection bladder; and returning the at least one elastomericsample collection bladder to a surface vessel for testing of theline-pack solution.
 15. The method of claim 14, further comprisingfiltering and treating any line-pack solution that is not collected inthe at least one elastomeric sample collection bladder prior todischarging that part of a line-pack fluid that is pumped out and notretained as part of a sample retained in the at least one elastomericsample collection bladder.
 16. The method of claim 14, furthercomprising redosing the pipeline with a chemical solution aftercollecting the sample.
 17. The method of claim 14, further comprisingusing the SV, ROV, or AUV to install a termination plug within at leastone end of the pipeline and remove an adjacent pipeline termination headto the surface.
 18. A method of removing a fluid content from a subseastructure, comprising the steps of: providing at least one productremoval bladder to the subsea structure, wherein the at least oneproduct removal bladder is fitted with at least one valve closure andwherein the at least one product removal bladder is dimensioned to draina quantity of the fluid content from the subsea structure; providing asubsea pipeline service skid (SPSS) including at least one high pressurepump dimensioned to deliver over 400 p.s.i. of pressure and a fluidconduit that terminates in an SPSS fluid connector dimensioned toconnect with the at least one valve closure of the at least one productremoval bladder; utilizing a Submersible Vehicle (SV), a Remote OperatedVehicle (ROV), or an Autonomous Underwater Vehicle (AUV) to connect theat least one product removal bladder and SPSS to the subsea structure;utilizing the at least one pump to move fluid content from the subseastructure into the at least one product removal bladder, and returningthe at least one product removal bladder to a surface vessel fordisposal.
 19. The method of removing a fluid content from a subseastructure of claim 18, wherein the at least one product removal bladderis disposed within a cage.
 20. A method of removing a fluid content froma subsea structure, comprising the steps of: providing at least oneproduct removal bladder to the subsea structure, wherein the at leastone product removal bladder is fitted with at least one valve closureand wherein the at least one product removal bladder is dimensioned todrain a quantity of the fluid content from the subsea structure;providing a subsea pipeline service skid (SPSS) including at least onepump and a fluid conduit that terminates in an SPSS fluid connectordimensioned to connect with the at least one valve closure of the atleast one product removal bladder; utilizing a Submersible Vehicle (SV),a Remote Operated Vehicle (ROV), or an Autonomous Underwater Vehicle(AUV) to connect the at least one product removal bladder and SPSS tothe subsea structure; utilizing the at least one pump to move fluidcontent from the subsea structure into the at least one product removalbladder, wherein the SPSS includes intake filters and the at least onepump is utilized to pump filtered seawater into the subsea structure andthereby push a fluid from the subsea structure into the at least oneproduct removal bladder; and returning the at least one product removalbladder to a surface vessel for disposal.